Ideally, while drilling a well into formations which may or may not contain commercially exploitable hydrocarbon deposits, one would like to identify whether:
the formation being drilled is porous, and thus a candidate for bearing hydrocarbons and capable of economical production rates; PA1 the fluid contained within the porous formation are hydrocarbons; and PA1 the hydrocarbons in the pores are light (C1--methane or C2--Ethane and of less interest) or are heavier (C3--Propane, C4--Butane and C5--Pentanes--the heavier hydrocarbons and thus of commercial interest). PA1 analysing the mud returning up the wellbore using a TG sensor for establishing TG values which increase with increasing concentrations of hydrocarbons; PA1 determining a dilution factor for the volume of mud being analysed by the TG sensor compared to the overall circulation of mud; PA1 determining a porosity factor for the drilled formation, preferably by normalizing the rate of BIT penetration by a reciprocal of the unit wellbore volume drilled; and PA1 normalizing the TG by the dilution factor over the porosity factor for establishing hydrocarbon saturation index values indicative of the fraction of the pore space which is hydrocarbon. PA1 analysing the mud returning up the wellbore using the TG sensor, PA1 analysing the mud returning up the wellbore using a DTG sensor for establishing DTG values which increase with increasing concentrations of light hydrocarbons and which decrease with increasing concentrations of heavier hydrocarbons; and PA1 determining the ratio of TG values over DTG values for establishing hydrocarbon ratio values indicative of the quality of the hydrocarbons.
Whether a formation is permeable or not is a function of whether the pores are connected. The relationship between porosity and Permeability is not reviewed in detail here.
Generally, when drilling an oil well, there is a rig drilling a wellbore down through a variety of `dry` and hydrocarbon-bearing formations. Drilling fluid or mud is pumped downhole through the drill string to the bit to flush any hydrocarbons and solids from around the bit. The mud flows up the annulus between the wellbore and the drilling string, to the surface for removal of solids and cuttings in an active mud system.
Mud carries back cuttings and solids and fluids associated with the formation currently being drilled. At the active mud system, a study of the solids and gases in the mud can be performed for determining an indication of the properties of the formations being penetrated. The mud can be analysed for grain distribution and rock type, and the gases carried with the mud can be analysed for hydrocarbon content.
The drilling rig typically provides additional information regarding the formation such as the drill string rpm (RPM), force on the bit (FOB), rate of penetration (ROP) and mud weight (MW) all of which suggest characteristics of the formation. Additional factors include the mud viscosity (MV) and mud filtrate (MF).
After drilling, gamma ray, electrical resistivity, and neutron testing tools are typically taken by running one or more tools downhole to the formation of interest. These tests are often referred to collectively as E-logs.
E-logs themselves can be indicative of the lithology (type of rock) and its relative porosity (Shale being low in porosity and sandstone being higher). Gamma Ray tools work through steel casing and measure natural radiation in formations. Gamma Rays tools can differentiate between shale and sand (shale being more radioactive than sand). Electrical resistivity tools to differentiate between the lower conductivity of hydrocarbon bearing and higher conductivity water-bearing formations. Neutron tools emit gamma rays to detect variations in the element of hydrogen in the formation.
The E-logs can be correlated with the mud analyses (such as hydrocarbon gas detection) to determine whether or not a formation which was traversed should be of interest or not.
Taken individually, mud gas analysis, drilling parameters and E-Logs may be insufficient to categorically state that the wellbore has been drilled into or has passed a zone of interest. In combination however, the independent factors are usually enlightening and interest on non-interest can be stated with some confidence.
Ideally however, identification of formations of interest would be obtained WHILE drilling. This needs to be accomplished by taking overall real-time measurements while drilling oil wells. Factors which need to be ascertained are, whether a formation is porous, whether fluids within any pores are hydrocarbon and if so, are they light or heavy hydrocarbons.
E-logs can be used to determine whether a formation is porous, unfortunately only obtained after drilling or with a costly and significant interruption. Additionally, while drilling, a geologist's report provides qualitative analysis only. Some drilling parameters indicate more porous rock such as experiencing a fast ROP, a lower FOB and higher achievable RPM.
Techniques for determining whether hydrocarbon in the pore is gas or oil include neutron tool E-logs, as described above, but are only available after the fact. While drilling however, gas can liberated from a slip stream of mud returning from the wellbore by separation of the gas from mud in a gas trap. The gas is analysed using real-time sensors. One sensor is a Total Gas sensor (TG) which measures any instance of hydrocarbons (substantially Methane (C1) through pentane (C5)--measured in ppm on a methane scale). TG is used as an indication whether any hydrocarbons are present at a certain depth. TG is unable to differentiate between light and heavy hydrocarbons however.
Accordingly, there is a demonstrated need in the industry for new techniques for determining whether a zone is of interest, before significantly overdrilling or missing a zone entirely.